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TRANSCRIPT
NYSE: DNR
Corporate Presentation October 2015
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2
About Forward-Looking Statements
The data contained in this presentation that are not historical facts are forward-looking statements that involve a number of risks and uncertainties. Such statements may relate to, among other things: long-term strategy; the length or severity of the recent oil price downturn; forecasts of capital expenditures, drilling activity and developmental activities; timing of carbon dioxide (CO2) injections and production response to such tertiary flooding projects; estimated timing of pipeline construction or completion or the cost thereof; anticipated dates of completion of industrial plants to be constructed or under construction and the initial date of capture and amount of anthropogenic CO2; estimates of liquidity, costs, forecasted production rate or peak production rates and the growth thereof; estimates of hydrocarbon reserve quantities and values, including potential and recoverable reserves, CO2 reserves, and helium reserves; projected future hydrocarbon prices or costs; estimated future cash flows, including from our hedging positions, or uses of cash; availability of capital or borrowing capacity; estimated rates of return and overall economics; and anticipated availability and cost of equipment and services. These forward-looking statements are generally accompanied by words such as “believe”, “estimated”, “preliminary”, “projected”, “potential”, “anticipated”, “forecasted”, “expected”, “assume” or other words that convey the uncertainty of future events or outcomes. These statements are based on management’s current plans and assumptions and are subject to a number of risk and uncertainties as further outlined in our most recent Form 10-K filed with the SEC. Therefore, actual results may differ materially from the expectations, estimates, forecasts, projections, or assumptions expressed in or implied by any forward-looking statement herein made by or on behalf of the Company.
Cautionary Note to U.S. Investors – Current SEC rules regarding oil and gas reserves information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2014 were estimated by DeGolyer and MacNaughton, an independent petroleum engineering firm. In this presentation, we make reference to probable and possible reserves, some of which have been estimated by our independent engineers and some of which have been estimated by Denbury’s internal staff of engineers. In this presentation, we also refer to estimates of original oil in place, resource or reserves “potential”, barrels recoverable, or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include estimates of reserves that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.
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• Proven process
• Lower-risk & long-life assets
• Tremendous resource potential
• Strategic CO2 supply
• >1,100 miles of CO2 pipelines
• Large inventory of oil fields
• Fund capex with cash flow
• Relatively low capital intensity
• Adjust to oil price environment
Long-Term Visibility
Capital Flexibility
Competitive Advantages
A Different Kind of Oil Company
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(Waterfloods)
Inject into
Oilfield
CO2 EOR Delivers Almost as Much
Production as Primary or Secondary Recovery(1)
Tertiary
Remaining Oil
Transport via
Pipeline
Primary
(1) Recovery of original oil in place based on history at Little Creek Field.
~20%
~18%
~17%
Secondary
(CO2 EOR)
Secure CO2 Supply
What is CO2 EOR & How Much Oil Does it Recover?
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Click to edit title style Denbury at a Glance
$1.0 billion
73,716
$8.7 billion
~17 Tcf
>1,100 miles
Market Cap (10/2/15)
Total Daily Production – BOE/d (2Q15)
Proved PV-10 (12/31/14) $94.99 NYMEX Oil Price
CO2 Supply 3P Reserves (12/31/14)
CO2 Pipelines Operated or Controlled
~1.2 BBOE
95%
Total 3P Reserves (12/31/14)
% Oil Production (2Q15)
$3.5 billion Total Debt (6/30/15)
$1.2 billion Credit Facility Availability (6/30/15)
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437.7 MBOE Total Proved Reserves (12/31/14)
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Click to edit title style Proactively Responding To a Lower Oil Price Environment
● Reduced capital spending by 50% for 2015 to $550MM (now est. at $520MM)
Expecting to generate free cash flow in 2015
Planning on utilizing liquidity to take advantage of potential opportunities
Building liquidity to further enhance our solid financial position
Resulting in relatively flat production targets for 2015 and likely 2016
● Focusing on operational initiatives and increasing efficiency
● Restructured bank debt covenants to provide flexibility over the next several years
● Suspended quarterly dividend payment of $0.0625 beginning in 4Q 2015
Will free up ~$22 million of cash per quarter which can be directed for other uses, among other things, debt reduction, increases in CapEx, or share repurchases
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Identify opportunities to significantly improve the economic value and profitability of Denbury’s fields.
Innovation & Improvement Teams (IITs)
Increase Field PV-10 and Cash Flow
Reduce LOE, CO2 Purchases & CAPEX
Process: ● Evaluate, improve operational processes (Production forecasting; reservoir management; knowledge sharing; facility modularization; reserves; and tertiary alternatives)
Increase sweep efficiency Use of 4D seismic to increase CO2 flooding Improve reservoir surveillance and geology descriptions Increased awareness of potential above and below target zones
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(1) Source: 2013 DOE NETL Next Gen EOR (2) Total estimated recoveries on a gross basis utilizing CO2 EOR.
Technically Recoverable(1,2)
(amounts in billions of barrels)
Permian 9-21
East & Central Texas 6-15
Mid-Continent 6-13
California 3-7
South East Gulf Coast 3-7
Rockies 2-6
Other 0-5
Michigan/Illinois 2-4
Williston 1-3
Appalachia 1-2
Total: 33-83
U.S. Lower-48 CO2 EOR Potential
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Existing or Proposed CO2 Source Owned or Contracted
Existing Denbury CO2 Pipelines
Denbury owned fields
WY
TX
MS
ND
Up to 16 Billion Gross Barrels Recoverable(1)
in Our Two CO2 EOR Target Areas
3.7 to 9.1 Billion Barrels
Estimated Recoverable in Gulf Coast Region(2)
Denbury-operated fields represent ~10% of total
potential(3)
2.8 to 6.6 Billion Barrels
Estimated Recoverable in Rocky Mountain Region(2)
(1) Total estimated recoveries on a gross basis utilizing CO2 EOR, based on a variety of recovery factors. (2) Source: 2013 DOE NETL Next Gen EOR (3) Using approximate mid-points of ranges, based on a variety of recovery factors.
MT
AL
Proposed Denbury CO2 Pipelines
LA
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Jackson Dome
Sonat MS Pipeline
Citronelle
(2)
Tinsley
Martinville
Davis Quitman
Heidelberg
Summerland Soso
Sandersville
Eucutta Yellow Creek Cypress Creek
Brookhaven
Mallalieu
Little Creek
Olive
Smithdale
McComb
Donaldsonville
Delhi
Lake St. John
Cranfield
Lockhart Crossing
Hastings
Conroe
Oyster Bayou
Delhi(3) 45 MMBbls
Tinsley(3) 46 MMBbls
Mature Area(3)
170 MMBbls
Oyster Bayou(3) 20 - 30 MMBbls
Conroe(3) 130 MMBbls
Summary(1)
Proved 179
Potential 365
Produced-to-Date(2) 99
Total MMBOEs(3) 643
Thompson
Heidelberg(3)
44 MMBbls
Houston Area(3)
Hastings 60 - 80 MMBbls Webster 60 - 75 MMBbls Thompson 30 - 60 MMBbls
150 - 215 MMBbls
Webster
Pipelines Denbury Operated Pipelines Denbury Proposed Pipelines
15 – 50 MMBoe 50 – 100 MMBoe > 100 MMBoe Denbury Owned Fields – Current CO2 Floods
Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates
Cumulative Production
Free State Pipeline
(1) Proved tertiary oil reserves based on year-end 12/31/14 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/14, using mid-point of ranges, based on a variety of recovery factors.
(2) Produced-to-date is cumulative tertiary production through 12/31/14. (3) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/14.
CO2 EOR in Gulf Coast Region: Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
~90 Miles Cost: ~$220MM
Green Pipeline ~325 Miles
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MONTANA
NORTH DAKOTA
SOUTH DAKOTA
WYOMING
Elk Basin
Shute Creek (XOM)
Lost Cabin (COP)
DGC Beulah
Riley Ridge (DNR)
Greencore Pipeline 232 Miles
Bell Creek(4) 40 - 50 MMBbls
Cedar Creek Anticline Area(4)
260 - 290 MMBbls
Grieve Field(4)
6 MMBbls Existing CO2 Pipeline
CO2 Sources Existing or Proposed CO2 Source Owned or Contracted
Hartzog Draw(4) 20 - 30 MMBbls
Summary(1)
Proved 37
Potential 313
Produced-to-Date(2) <1
Total MMBbls 351
LaBarge Area
368 BCF Nat Gas
13 BCF Helium
3.0 TCF CO2(3)
Pipelines Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others
15 – 50 MMBoe 50 – 100 MMBoe > 100 MMBoe Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates
Cumulative Production
(1) Proved tertiary oil reserves based on year-end 12/31/14 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/14, using approximate mid-points of ranges, based on a variety of recovery factors.
(2) Produced-to-date is cumulative tertiary production through 12/31/14. (3) Reported on a gross working interest or 8/8th’s basis, except for overriding royalty interest in LaBarge Field. (4) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/14.
CO2 EOR in Rocky Mountain Region: Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
Greencore Pipeline 232 Miles
~250 Miles Cost:~$500MM
~130 Miles Cost:~$225MM
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0
200
400
600
800
1,000
1,200
2013 2014 2015 2016 2017 2018
CO
2 Vol
umes
, MM
cf/D
ay
CO2 Supply to Support Gulf Coast Growth
Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary. (1) Estimated as of 12/31/14.
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JACKSON DOME PROVED RESERVES(1)
~5.7 TCF
INDUSTRIAL SOURCE CO2 SUPPLY - Future Construction
• Probable & Possible Reserves: ~1.7 TCF • Improved Recovery of Proved Reserves: ~0.8 TCF
PLUS
Forecasted Gulf Coast CO2 Demand
Q2 2015 Actual Demand Current CO2 demand is significantly less than forecasted CO2 demand. We are evaluating our future CO2 demand
requirements as part of our ongoing IIT processes.
• Recycle: ~3 TCF • Additional Industrial-Source CO2
Additional CO2 Potential(1) (not reflected in graph)
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Positive Results in Q2 from IIT Field Reviews – Using Less CO2 Without Near-Term Negative Production Impact
$1.32 Reduction to LOE per Bbl due to Lower CO2 Usage
Potential Long-Term CapEx Savings – Less Drilling at Jackson Dome
CO2 Efficiencies = Significant Savings
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979
762
Q1 2015 Q2 2015
Total Company CO2 Volumes MMcf/d
$5.39
$4.69
Q1 2015 Q2 2015
CO2 Price
Impact
Cost Reduction
Due to Volumes
$0.62
CO2 Costs(1) $/Bbl on Tertiary Operating Costs
$0.62
($1.32)
(1) See slide 34 for additional detail on tertiary operating costs.
22% Decline
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Click to edit title style CO2 Supply to Support Rocky Mountain Growth
LaBarge Area ● Estimated field size: 750 square miles ● Estimated 100 TCF of CO2 recoverable
Riley Ridge – Denbury Operated ● Production expected to resume in 2016 ● 100% WI in ~9,800 acre Riley Ridge Federal Unit ● 33% WI in ~28,000 acre Horseshoe Unit ● Estimated 1.8 TCF CO2 proved reserves(1)
Shute Creek – XOM Operated ● 1/3 overriding royalty ownership interest in XOM’s
CO2 reserves ● Based on XOM’s current plant capacity and
availability, Denbury could receive up to ~115 MMcf/d of CO2 from the plant
● Estimated 1.2 TCF CO2 proved reserves(1)
LaBarge Area
368 BCF Nat Gas
13 BCF Helium
3.0 TCF CO2(1)
Composition of Produced Gas Stream: ~65% CO2; 16%-18% Natural Gas; <1%
Helium, and various other gases
(1) Reported on a gross working interest or 8/8th’s basis as of 12/31/14, except for overriding royalty interest in LaBarge Field.
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$0.00
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
4Q13 1Q15 2Q15 4Q13 1Q15 2Q15
$7.53 $4.69 $4.07
$2.71
$6.70
$6.27 $5.49
$5.28
$5.47
$4.89 $5.73
$5.33
$5.72
$2.00
$6.07
$2.42
Other Workovers Chemicals Repairs & Maintenance Labor & Overhead Power & Fuel CO2 Costs
Reducing Operating Costs(1)(2)
$/Bbl $28.72
$22.70
$26.24
$21.08
(1) See slides 33 & 34 for additional detail on tertiary only and total operating costs. (2) Excludes $16MM related to Delhi Field remediation charges in 4Q13.
Tertiary Operating Costs(1) Total Operating Costs(1)
$20.52 $19.70
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x
2x
4x
6x
8x
10x
12x
14x
16x
18x
20x
2011
2012
2013
2014
-
Unique Asset Structure Relative to Other Independents(3)
(1) Reserve life index calculated as total proved oil equivalent reserves at prior year-end divided by total annual oil equivalent production. (2) Source: Credit Suisse analysis dated June 2014. (3) APA, APC, BBG, BEXP, BP, BRY, CFW, CHK, CLR, COG, CPE, CRK, CRZO, CVX, CXO, DNR, DVN, ECA, EOG, EQT, EXXI, FST, GMXR, GPOR, HES, HK, KOG, KWK, MCF, MMR, MRO, MUR, NBL,
NFX, NOG, NXY, OXY, PDCE, PETD, PQ, PVA, PXD, PXP, REXX, ROSE, RRC, SD, SFY, SGY, SM, SWN, UNT, UPL, VQ, WLL, WTI, XCO, XEC, XOM and XTO.
Reserve life index(1) 1st year of decline rate by basin(2)
EOR Assets Non-EOR Assets
Inclining production for several
years before initial
decline
DNR Selected Companies(3)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
EOR
- Li
ttle
Cre
ek
EOR
- B
rook
have
n
EOR
- M
artin
ville
EOR
- S
oso
EOR
- M
alla
lieu
Mis
siss
ippi
an L
ime
Wol
fber
ry
Yeso
Thre
e Fo
rks/
San
ish
Bone
Spr
ing
- NM
Nio
brar
a - W
atte
nber
g
Bone
Spr
ing
(3rd
) - W
TX
Wol
fcam
p-M
idla
nd (H
Z)
Eagl
e Fo
rd -
Liqu
ids
Ric
h
Gra
nite
Was
h Li
quid
s R
ich
Utic
a - L
iqui
ds R
ich
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(1) See slide 2 for full disclosure relative to forward-looking statements. (2) Includes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods. (3) Based on $0.0625 per share quarterly dividend payable 1Q through 3Q 2015. Dividend suspended beginning in 4Q 2015. (4) Projected range before adjusting for estimated annual impact of weather-related downtime due to flooding at Thompson Field of approximately 250 BOE/d, and shutting-in uneconomic wells which equates to
approximately 500 BOE/d.
Capital Budget: Reduced from ~$550MM to ~$520MM
2015 Guidance(1)
Tertiary Floods ~$270MM
Non-Tertiary ~$100MM CO2 Pipelines
~$15MM
CO2 Sources ~$30MM
Operating area 2014
(BOE/d)
2015E (BOE/d)
Tertiary Oil Fields 41,079 42,100 – 43,700
Non-Tertiary Oil Fields 33,353 30,400 – 31,800(4)
Total Estimated Production 74,432 72,500 – 75,500(4)
Other Capitalized
Items(2)
~$105MM
Estimated Production
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Dividends(3)
~$66MM
Recent Production Impacts*
Weather-Related Downtime (Thompson Field)
Shut-In Uneconomic Wells
Daily Production Impact ~1,500 BOE/d ~1,000 BOE/d
Approximate Duration ~60 days (June-July 2015) 2H 2015
Estimated Annual Impact ~250 BOE/d ~500 BOE/d
*Due to these impacts, we currently expect total 2015 annual production will be in the lower half of the estimated production range
Developmental project spending reduced by $50MM Other capitalized items increased by $20MM
CO2 Pipelines ~$15MM
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(1) See slide 32 for additional detail on oil derivative contracts. (2) Averages are volume weighted. (3) Prices for LLS contracts were reduced by $3 to reflect an assumed differential to NYMEX. (4) If oil prices were to average less than the sold put price, the average downside hedge price for volumes with sold puts would be reduced by the amount prices averaged below the sold put price.
2015 2016
3Q 4Q 1Q 2Q 3Q
Crude Oil (WTI NYMEX Equivalent)(2)(3)
Total Oil Volumes Hedged (Bbls/d) 58,000 38,000 36,000 34,000 7,500
Average Downside Hedge Price(4) $84.80 $88.80 $88.99 $69.88 $55.00
Average Upside Hedge Price $93.07 $95.22 $95.47 $74.34 $71.07
Average Sold Put Price(4) $65.12 $66.74 $66.94 $67.33 -
Volumes with Sold Puts (Bbls/d) 26,000 38,000 36,000 12,000 -
Natural Gas (NYMEX)
Average Floor Price $4.00 $4.00 - - -
Average Ceiling Price $4.51 $4.51 - - -
Total Volumes Hedged (MMBtus/d) 8,000 8,000 - - -
Commodity Hedge Summary as of October 2, 2015(1)
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6/30/15 Total Net Debt ($MM) $3,505 TTM EBITDA(3) ($MM) $1,231 Total Net Debt to TTM EBITDA(3) 2.8x Total Net Debt to Total Capitalization 44.3%
Bank Credit Facility
6.375%
5.50%
~1.50%(4)
4.625%
-
400
800
1,200
1,600
2,000
2,400
2,800
2015 2016 2017 2018 2019 2020 2021 2022 2023
($MM)
(1) Balances as of June 30, 2015. (2) Excludes $2.7MM Encore senior subordinated notes, estimated pipeline financings of $216.6MM due between 2015 and 2028, and estimated capital lease obligations of $90.0MM due between 2015
and 2021. (3) A non-GAAP measure; please visit our website for a full reconciliation. EBITDA as calculated under our senior subordinated notes. (4) Floating rate, 1-Month LIBOR rate of 0.2% plus 1.25% margin.
Drawn
Undrawn & Available
$400
$1,250 $1,200
No Significant Near-Term Debt Maturities
Debt Maturity Schedule(1)(2)
$350
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Potential Additional Credit
No scheduled fall redetermination on our bank credit facility.
Next scheduled redetermination in May 2016.
Sr. Subordinated Notes
Borrowing Base: $2.6 Billion
Elected Commitment Amount: $1.6 Billion
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We believe in our assets and strategy and know we must continue to improve our operational efficiency:
● Innovation teams and other key operational initiatives ● Reduce capital spending in lower oil price environment
Build liquidity to protect solid financial position Look to take advantage of future opportunities
● Hedges protect 2015 cash flows
Long-Term Visibility
Capital Flexibility
Competitive Advantages
DNR
Leveraging Strengths & Adjusting to Lower Oil Prices
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Appendix
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Click to edit title style Why is CO2 EOR our core focus?
● High Confidence of Oil Target
Over 100 million barrels (gross) produced by Denbury to date
● CO2 Flooding Recovers Oil (CO2 ♥’s Crude Oil)
First commercial CO2 EOR flood started production in 1972
Over 1.5 billion barrels produced to date in the U.S.(1)
Current estimated production in the U.S. is ~300 MBbls/d(2)
● A Very Repeatable Process with a lot of Running Room
Up to 16 billion barrels (gross) recoverable with CO2 EOR in our two operating areas(3)
~900 million barrels (net) of 3P CO2 EOR reserves in our portfolio today
(1) Oil & Gas Journal, Dec. 7, 2009. (2) Oil & Gas Journal, July 2, 2012. (3) Source: 2013 DOE NETL Next Gen EOR.
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Click to edit title style CO2 EOR is a Proven Process
Significant CO2 Suppliers by Region Gulf Coast Region • Jackson Dome, MS (Denbury Resources) Permian Basin Region • Bravo Dome, NM (Kinder Morgan, Occidental) • McElmo Dome, CO (ExxonMobil, Kinder Morgan) • Sheep Mountain, CO (ExxonMobil, Occidental) Rockies Region • LaBarge, WY (ExxonMobil, Denbury Resources) • Lost Cabin, WY (ConocoPhillips) Canada • Dakota Gasification – Industrial-Source CO2 (Cenovus,
Apache)
Significant CO2 EOR Operators by Region
Gulf Coast Region • Denbury Resources Permian Basin Region • Occidental • Kinder Morgan Rockies Region • Denbury Resources • FDL/KKR Canada • Cenovus • Apache
Jackson Dome
Bravo Dome
LaBarge
Lost Cabin
DGC
McElmo Dome
Significant CO2 Source 0
50
100
150
200
250
300
1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014
MB
bls/
d
Gulf Coast/Other
Mid-Continent
Rocky Mountains
Permian Basin
CO2 EOR Oil Production by Region (1)
(1) Source: Advanced Resources International
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Click to edit title style CO2 Operations: Oil Recovery Process
CO2 PIPELINE - from Jackson Dome
CO2 moves through formation mixing with oil droplets, expanding them and moving them to producing wells.
INJECTION WELL - Injects CO2 in dense phase
PRODUCTION WELLS Produce oil, water and CO2 (CO2 is recycled)
Model for Oil Recovery Using CO2 is +/- 17% of Original Oil in Place (Based on Little Creek)
Primary recovery = +/- 20% Secondary recovery (waterfloods) = +/- 18% Tertiary (CO2) = +/- 17%
Oil Formation
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Air Products • Port Arthur, Texas • Hydrogen Plant • Producing Since: 1Q 2013 • Quantity: ~50 MMcf/d
PCS Nitrogen • Geismar, Louisiana • Ammonia Products • Producing Since: 2Q 2013 • Quantity: ~20 MMcf/d
Mississippi Power (Pending Startup) • Kemper County, MS • Gasifier • Estimated Capture Date: ~2016 • Quantity: ~115 MMcf/d
Currently Producing or Pending Startup
Denbury Owned Fields – Current CO2 Floods
Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates
CO2 Captured from Industrial Sources
Air Products PCS Nitrogen
MS Power
Natural CO2 Source
AL
Gulf Coast Industrial Partners
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Click to edit title style Actual Industry Recovery Curves
Range of Recovery 10%-18%
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Click to edit title style Actual Curves – Denbury Mature Fields
Range of Recovery
11%-20+%
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Click to edit title style CO2 EOR – Superior Production Profile
0
2,000
4,000
6,000
8,000
10,000
12,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18
Pro
duct
ion
(Bbl
s/d)
Years
Gulf Coast EOR FieldBakken
Projected Production Profile with Same Capital Spending Capital Spending per Year Based on EOR
Spending Pattern
Year $MM 1 83 2 83 3 60 4 60 5 68 6 52 7 52 8 52 9 45
Total $555
Note: Assumes 700 BOEPD initial 30 day rate for Bakken wells.
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Operating area 2012 2013 2014 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 2015E(1)
Tertiary Oil Fields 35,206 38,477 41,079 39,057 38,752 37,513 38,603 39,892 40,897 41,627 41,873 41,827 42,584 42,100 – 43,700
Cedar Creek Anticline 8,503 16,572 18,834 8,745 19,935 18,872 18,601 19,007 19,155 18,623 18,553 18,522 18,089 18,000 – 18,800
Other Rockies Non-Tertiary 3,231 4,862 4,850 5,163 4,958 4,819 4,516 4,831 5,392 4,594 4,591 4,750 4,433 4,100 – 4,300
Gulf Coast Non-Tertiary 9,902 10,332 9,669 10,858 10,407 10,327 9,746 9,988 9,876 8,966 9,858 9,257 8,610(2) 8,300 – 8,700
Total Continuing Production 56,842 70,243 74,432 63,823 74,052 71,531 71,466 73,718 75,320 73,810 74,875 74,356 73,716 72,500 – 75,500
Divested Properties 14,847 --- --- --- --- --- --- --- --- --- --- --- ---
Total Production 71,689 70,243 74,432 63,823 74,052 71,531 71,466 73,718 75,320 73,810 74,875 74,356 73,716
(1) See slide 2 for full disclosure relative to forward-looking statements. (2) Thompson Field’s production was shut-in during the month of June due to weather-related downtime caused by flooding. This downtime impacted Q2’15 production by approximately 500 BOE/d and we
anticipate an approximate 200 BOE/d impact to production in Q3’15 as Thompson Field did not return to full production until the end of July.
Production by Area (BOE/d)
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Click to edit title style Tertiary Production by Field
Average Daily Production (BOE/d) Field 2012 2013 2014 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 Brookhaven 2,692 2,223 1,759 1,877 1,818 1,767 1,579 1,612 1,691 Little Creek Area 1,091 865 683 750 696 668 616 590 589 Mallalieu Area 2,338 2,050 1,799 1,837 1,839 1,869 1,653 1,574 1,537 McComb Area 1,785 1,515 1,291 1,287 1,361 1,340 1,175 1,016 1,043 Lockhart Crossing 1,176 998 908 924 933 934 844 832 1,024 Martinville 507 414 358 369 319 357 387 385 386 Eucutta 2,868 2,514 2,137 2,181 2,150 2,224 1,995 1,905 2,054 Soso 1,989 1,946 1,679 1,720 1,747 1,664 1,588 1,646 1,596 Cranfield 1,159 1,278 1,203 1,233 1,100 1,226 1,254 1,241 1,250 Mature Area 15,605 13,803 11,817 12,178 11,963 12,049 11,091 10,801 11,170
Tinsley 7,947 8,051 8,507 8,430 8,518 8,310 8,767 8,928 8,740
Heidelberg 3,763 4,466 5,707 5,325 5,609 5,721 6,164 6,027 5,885
Delhi(1) 4,315 5,149 4,340 4,708 4,543 4,377 3,743 3,551 3,623
Hastings 2,188 3,984 4,777 4,618 4,759 4,917 4,811 4,694 5,350
Oyster Bayou 1,388 2,968 4,683 4,055 4,415 4,605 5,638 5,861 5,936
Bell Creek --- 56 1,248 578 1,090 1,648 1,659 1,965 1,880
Total Tertiary Production 35,206 38,477 41,079 39,892 40,897 41,627 41,873 41,827 42,584
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(1) Beginning with the fourth quarter of 2014, average daily Delhi Field production amounts reflect the reversionary assignment of approximately 25% of our interest in that field effective November 1, 2014. The effectiveness, timing, and scope of the reversionary assignment are subject to ongoing litigation, the ultimate outcome of which cannot be predicted.
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Crude Oil Differentials 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15
Tertiary Oil Fields
Gulf Coast Region $15.82 $11.23 $4.32 $0.32 $3.68 $1.15 $2.37 $1.52 $(0.22) $2.04
Rocky Mountain Region --- --- (8.25) (15.56) (7.06) (8.60) (11.24) (6.88) (2.09) (2.81)
Cedar Creek Anticline (2.65) (6.44) (6.53) (13.39) (8.66) (10.26) (11.69) (9.07) (7.95) (6.48)
Other Rockies Non-Tertiary (8.71) (8.53) (9.68) (17.26) (11.52) (12.44) (13.75) (11.52) (9.84) (8.48)
Gulf Coast Non-Tertiary 12.84 7.61 (0.84) (2.02) (0.19) (1.50) 0.91 (0.50) (0.71) 0.68
Denbury Totals $11.17 $4.78 ($0.03) ($4.57) ($0.91) ($3.03) ($2.53) ($2.24) ($2.81) ($0.89)
NYMEX Oil Differential Summary
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(1) Averages are volume weighted. (2) If oil prices were to average less than the sold put price, the average swap or floor price would be reduced by the amount oil prices averaged below the sold put price.
2015 2016 3Q 4Q 1Q 2Q 3Q
WTI NYMEX Swaps
Volumes Hedged (Bbls/d) 10,000 12,000 12,000 13,500 ---
Average Swap Price (1) $90.02 $92.42 $92.43 $66.06 ---
Volumes with Sold Puts 10,000 12,000 12,000 2,000 ---
Average Sold Put Price (1),(2) $65.30 $68.00 $68.00 $68.00 ---
Argus LLS Swaps
Volumes Hedged (Bbls/d) 16,000 8,000 8,000 9,500 ---
Average Swap Price (1) $93.65 $94.94 $94.81 $82.92 ---
Volumes with Sold Puts 16,000 8,000 8,000 6,000 ---
Average Sold Put Price (1),(2) $68.00 $68.00 $68.50 $70.00 ---
WTI NYMEX Collars & 3-Ways
Volumes Hedged (Bbls/d) 28,000 10,000 10,000 7,000 4,500
Average Floor X Ceiling Price (1),(2) $80.00X$95.05 $85.00X$99.00 $85.00X$99.85 $63.57X$78.01 $55.00X$71.22
Volumes with Sold Puts --- 10,000 10,000 2,000 ---
Average Sold Put Price (1),(2) --- $68.00 $68.00 $68.00 ---
Argus LLS Collars & 3-Ways
Volumes Hedged (Bbls/d) 4,000 8,000 6,000 4,000 3,000
Average Floor X Ceiling Price (1),(2) $85.00X$99.50 $88.00X$100.99 $88.00X$102.10 $73.00X$85.63 $58.00X$73.85
Volumes with Sold Puts --- 8,000 6,000 2,000 ---
Average Sold Put Price (1),(2) --- $68.00 $68.00 $70.00 ---
Oil Hedge Detail as of October 2, 2015
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Click to edit title style Analysis of Total Operating Costs
Correlation w/Oil
1Q13 $/BOE
2Q13 $/BOE
3Q13 $/BOE
4Q13 $/BOE
1Q14 $/BOE
2Q14 $/BOE
3Q14 $/BOE
4Q14 $/BOE
1Q15 $/BOE
2Q15 $/BOE
CO2 Costs Direct $4.15 $3.21 $3.58 $4.07 $3.88 $4.14 $3.72 $3.43 $3.03 $2.71
Power & Fuel Partially 5.33 5.41 5.21 5.49 6.14 5.97 5.83 5.78 5.88 5.28
Labor & Overhead None 5.74 5.36 5.57 5.73 5.44 5.40 5.57 5.34 5.45 5.33
Repairs & Maintenance None 1.31 1.02 1.55 1.42 1.36 1.22 1.50 1.72 1.44 1.22
Chemicals Partially 1.62 1.61 1.49 1.71 1.41 1.28 1.40 1.40 1.14 1.23
Workovers Partially 4.26 4.38 4.19 6.07 5.41 3.80 4.39 3.35 2.71 2.42
Other None 2.06 1.35 1.65 1.75 2.04 2.01 1.91 1.62 1.43 1.51
Total Excluding Delhi remediation(1) $24.47 $22.34 $23.24 $26.24 $25.68 $23.82 $24.32 $22.64 $21.08 $19.70
Total Including Delhi remediation --- $32.73 $27.50 $28.67 --- --- $22.86 $23.04 --- ---
NYMEX Oil Price $94.42 $94.14 $105.94 $97.57 $98.60 $103.07 $97.31 $73.04 $48.83 $57.81
Realized Oil Price $105.59 $98.92 $105.91 $93.00 $97.69 $100.04 $94.78 $70.80 $46.02 $56.92
(1) Excludes $70MM, $28MM, $16MM, ($10MM), and $3MM related to Delhi remediation charges and insurance reimbursements in 2Q13, 3Q13, 4Q13, 3Q14, and 4Q14, respectively.
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Correlation w/Oil
1Q13 $/Bbl
2Q13 $/Bbl
3Q13 $/Bbl
4Q13 $/Bbl
1Q14 $/Bbl
2Q14 $/Bbl
3Q14 $/Bbl
4Q14 $/Bbl
1Q15 $/Bbl
2Q15 $/Bbl
CO2 Costs Direct $6.78 $6.13 $6.82 $7.53 $7.17 $7.63 $6.55 $6.18 $5.39 $4.69
Power & Fuel Partially 6.46 6.85 6.52 6.70 7.76 7.72 7.21 7.17 7.30 6.27
Labor & Overhead None 4.43 4.56 5.08 5.47 4.98 5.11 5.17 4.91 5.03 4.89
Repairs & Maintenance None 1.15 0.72 1.11 0.95 0.76 0.80 1.07 0.98 1.15 0.86
Chemicals Partially 1.65 1.57 1.47 1.86 1.43 1.31 1.29 1.42 1.07 1.24
Workovers Partially 2.94 3.09 3.25 5.72 4.36 2.75 2.76 2.80 2.06 2.00
Other None 1.29 0.60 0.83 0.49 0.75 1.25 0.93 0.64 0.70 0.57
Total excluding Delhi remediation(1) $24.70 $23.52 $25.08 $28.72 $27.21 $26.57 $24.98 $24.10 $22.70 $20.52
Total including Delhi remediation --- $43.37 $33.19 $33.22 --- --- $22.40 $24.82 --- ---
NYMEX Oil Price $94.42 $94.14 $105.94 $97.57 $98.60 $103.07 $97.31 $73.04 $48.83 $57.81
Realized Tertiary Oil Price $110.24 $105.38 $110.24 $97.82 $102.13 $103.96 $99.14 $74.22 $48.52 $59.63
(1) Excludes $70MM, $28MM, $16MM, ($10MM), and $3MM related to net Delhi remediation charges and insurance reimbursements in 2Q13, 3Q13, 4Q13, 3Q14, and 4Q14, respectively.
Analysis of Tertiary Only Operating Costs
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(1) Excludes DD&A on CO2 wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO2 costs.
CO2 Cost(1) & NYMEX Oil Price
35
$40
$50
$60
$70
$80
$90
$100
$110
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
$0.40
$0.45
Q111
Q211
Q311
Q411
Q112
Q212
Q312
Q412
Q113
Q213
Q313
Q413
Q114
Q214
Q314
Q414
Q115
Q215
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EX C
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OPEX Purchases Tax NYMEX Crude Oil